RAPID CITY, S.D.--(BUSINESS WIRE)--Black Hills Corp. (NYSE: BKH) today announced 2012 third quarter
financial results. Income from continuing operations, as adjusted, was
$18.7 million, or $0.42 per diluted share, compared with $13.7 million,
or $0.35 per diluted share, for the same period in 2011 (this is a
non-GAAP measure and an accompanying schedule for the GAAP to non-GAAP
adjustment reconciliation is provided).

“Two key strategic utility projects advanced during the quarter”

“Our businesses performed very well in the third quarter, with adjusted
earnings per share up 20 percent,” said David R. Emery, chairman,
president and chief executive officer of Black Hills Corp. “We had
continued strong earnings contributions from our electric utilities, and
I am particularly pleased with the ongoing earnings improvements in our
power generation and coal mining segments. Our oil and gas segment
reported strong production gains that were offset by lower average
natural gas prices and higher depletion expenses.

“During the quarter, we closed on the sale of our Williston Basin oil
and gas assets for net cash proceeds of $227 million. We reported a
$17.7 million after-tax gain from the sale in the quarter. We believe
that the sales price and the overall transaction provided an exceptional
value for our shareholders.

“Given our continued strong performance, we expect 2012 earnings from
continuing operations, as adjusted, to be toward the upper half of our
$1.90 to $2.10 per share range. We also expect strong earnings growth in
2013 and are issuing guidance of $2.20 to $2.40 per share from
continuing operations, as adjusted.”

Three Months Ended Sept. 30,

Nine Months Ended Sept. 30,

(in millions, except per share amounts)

2012

2011

2012

2011

Non-GAAP *:

Income from continuing operations, as adjusted

$

18.7

$

13.7

$

62.3

$

48.0

Income (loss) from discontinued operations, net of tax

(0.2

)

0.6

(6.8

)

2.5

Net income, as adjusted (non-GAAP)

$

18.5

$

14.3

$

55.5

$

50.5

Earnings per share from continuing operations, as adjusted, diluted

$

0.42

$

0.35

$

1.41

$

1.21

Earnings (loss) per share, discontinued operations, net of tax

—

0.02

(0.16

)

0.07

Earnings per share, as adjusted, diluted (non-GAAP)

$

0.42

$

0.37

$

1.25

$

1.28

GAAP:

Income from continuing operations

$

34.6

$

(11.2

)

$

57.6

$

21.6

Income (loss) from discontinued operations, net of tax

(0.2

)

0.6

(6.8

)

2.5

Net income

$

34.5

$

(10.5

)

$

50.8

$

24.1

Earnings per share from continuing operations, diluted

$

0.78

$

(0.29

)

$

1.31

$

0.54

Income (loss) from discontinued operations, net of tax

—

0.02

(0.16

)

0.07

Earnings per share, diluted

$

0.78

$

(0.27

)

$

1.15

$

0.61

* This is a Non-GAAP measure, and an accompanying schedule for the GAAP
to Non-GAAP adjustment reconciliation is provided below.

“Two key strategic utility projects advanced during the quarter,” Emery
said. “Cheyenne Light and Black Hills Power received final approvals and
permits to build the 132 megawatt, $237 million natural gas-fired
Cheyenne Prairie Generating Station in Cheyenne, Wyo., and Colorado
Electric’s Busch Ranch wind project south of Pueblo, Colo. was placed
into service on Oct. 16.

“In October, two of the three credit rating agencies changed their
ratings outlook for Black Hills Corp. and Black Hills Power from stable
to positive. We believe the outlook change recognizes our lower business
risk profile and debt reduction efforts.

“We executed well in the third quarter with solid operating performance
and improved earnings. Our cost-containment efforts to mitigate the
earnings challenges of the first quarter are yielding positive results,
and those efforts will continue throughout the remainder of 2012.”

Cheyenne Light and Black Hills Power received final approvals and
permits for the Cheyenne Prairie Generating Station. The Wyoming
Public Service Commission approved the certificate of public
convenience and necessity on July 31 authorizing the construction,
operation and maintenance of a new 132 megawatt, $237 million natural
gas-fired electric generating facility in Cheyenne, Wyo. The state of
Wyoming issued the air permit for the project on Aug. 31, and the U.S.
Environmental Protection Agency issued the greenhouse gas air permit
on Sept. 27. Upon receipt of this final permit, the major equipment
for the project was ordered. Commencement of construction is expected
in spring 2013. Project costs for plant construction and associated
transmission are estimated at $222 million, with up to $15 million of
construction financing costs, for a total of $237 million.

On Oct. 30, Cheyenne Light and Black Hills Power received approval
from the Wyoming Public Service Commission to use a construction
financing rider for Cheyenne Prairie Generating Station in lieu of the
traditional allowance for funds used during construction. The rider
allows Cheyenne Light and Black Hills Power to earn and collect a rate
of return during the construction period on the approximately 60
percent of the project cost related to serving Wyoming customers. The
company is evaluating filing for a similar rider in South Dakota.

On Oct. 16, Colorado Electric’s 29 megawatt Busch Ranch wind project
south of Pueblo, Colo., commenced commercial operation. Colorado
Electric’s share of the project’s cost is approximately $26 million.
On Sept. 18, the company completed the sale of a 50 percent undivided
ownership interest in the project to the co-owner.

On Aug. 6, Black Hills Power and Colorado Electric announced plans to
suspend plant operations at some of their older coal-fired and natural
gas-fired facilities. In addition, the companies identified retirement
dates for the older coal-fired power plants because of state and
federal environmental regulations. The affected plants are listed in
the table below with their operations suspension date (if applicable)
and their ultimate retirement date (if identified).

Type of

Age of Plant

Plant

Company

Megawatts

Plant

Suspend Date

Retirement Date

(in years)

Osage

Black Hills Power

34.5

Coal

Oct. 1, 2010

March 21, 2014

64

Ben French

Black Hills Power

25.0

Coal

Aug. 31, 2012

March 21, 2014

52

Neil Simpson I

Black Hills Power

21.8

Coal

NA

March 21, 2014

43

W.N. Clark

Colorado Electric

40.0

Coal

Dec. 31, 2012

Dec. 31, 2013

57

Pueblo Unit #5

Colorado Electric

9.0

Gas

Dec. 31, 2012

to be determined

71

Pueblo Unit #6

Colorado Electric

20.0

Gas

Dec. 31, 2012

to be determined

63

On July 30, Colorado Electric filed its electric resource plan with
the Colorado Public Utilities Commission seeking to develop and own
replacement capacity for the retirement of the coal-fired W.N. Clark
power plant, which was previously ordered to be retired by the
commission to comply with the Colorado Clean Air – Clean Jobs Act. The
commission dismissed the initial filing and directed Colorado Electric
to refile the ERP by Jan. 18, 2013 in order to address alternatives
for the replacement capacity for its coal-fired W.N. Clark power
plant, as well as the retirement of Pueblo No. 5 and No. 6. The
commission also directed Colorado Electric to request certificates of
public convenience and necessity for any replacement capacity that
Colorado Electric seeks to develop and own.

On June 4, Colorado Gas filed a request with the Colorado Public
Utilities Commission for an increase in annual gas revenues to recover
capital investments and increased operation and maintenance expenses.
The commission required this rate case filing as part of a previous
settlement agreement when Black Hills Corp. purchased Colorado Gas.
All parties reached a rate case settlement, and the settlement hearing
was held on Oct. 12, 2012. A decision is expected in the first quarter
of 2013. The settlement, if approved, includes a $0.2 million revenue
increase, a return on equity of 9.6 percent, a cost of debt of 7.2
percent, and a capital structure of 50 percent equity and 50 percent
debt.

Weather was a contributing factor for utility results in the third
quarter. Our service territories reported warmer weather, as measured
by degree days, compared with the 30-year average and the same period
last year. Although temperatures were above normal, weather-related
demand was tempered by significantly lower humidity in the company’s
service territories in 2012 compared with 2011.

Non-regulated Energy

On Sept. 27, the company’s oil and gas business segment sold
approximately 85 percent of its Williston Basin assets for net cash
proceeds of approximately $227 million.

Corporate

On Oct. 31, the company redeemed $225 million of senior unsecured, 6.5
percent notes which were originally scheduled to mature on May 15,
2013.

On Oct. 30, Black Hills Corp. declared a quarterly dividend of $0.37
per share, equivalent to an annual dividend rate of $1.48 per share.
Through 2012, the company has increased its dividend for 42
consecutive years.

On Oct. 16, Standard & Poor’s Ratings Services changed its credit
ratings outlook for Black Hills Corp. and Black Hills Power from
stable to positive. On Oct. 18, Moody’s Investors Service also changed
its credit ratings outlook for Black Hills Corp. and Black Hills Power
from stable to positive.

BLACK HILLS CORPORATION

CONSOLIDATED FINANCIAL RESULTS

(Minor differences may result due to rounding.

Prior period information has been revised to reclassify
information related to discontinued operations.)

(in millions)

Three Months Ended Sept. 30,

Nine Months Ended Sept. 30,

2012

2011

2012

2011

Net income (loss):

Utilities:

Electric

$

14.6

$

15.8

$

37.5

$

34.6

Gas

—

0.6

16.4

24.3

Total Utilities Group

14.6

16.4

53.9

58.9

Non-regulated Energy:

Power generation

5.1

0.3

16.0

2.1

Coal mining

1.7

0.5

3.9

(1.1

)

Oil and gas (a)

17.4

0.2

(2.2

)

(0.6

)

Total Non-regulated Energy Group

24.2

1.0

17.7

0.4

Corporate and Eliminations (b) (c)

(4.2

)

(28.6

)

(14.0

)

(37.7

)

Income from continuing operations

34.6

(11.2

)

57.6

21.6

Income (loss) from discontinued operations, net of tax (c)

(0.2

)

0.6

(6.8

)

2.5

Net income (loss)

$

34.5

$

(10.5

)

$

50.8

$

24.1

(a)

Financial results for the three and nine months ended Sept. 30, 2012
include a $17.7 million after-tax gain on sale of our Williston
Basin assets and the nine months ended Sept. 30, 2012 include a
non-cash after-tax ceiling test impairment of $17.3 million.

(b)

Financial results include a $0.4 million net after-tax non-cash
mark-to-market gain and a $1.9 million net after-tax non-cash
mark-to-market loss on interest rate swaps for the three and nine
months ended Sept. 30, 2012, respectively, and a $24.9 million and
$26.4 million net after-tax non-cash mark-to-market loss on interest
rate swaps for the three and nine months ended Sept. 30, 2011,
respectively.

(c)

Certain indirect corporate costs and inter-segment interest expense
previously charged to our Energy Marketing segment could not be
reclassified to discontinued operations and accordingly have been
presented within Corporate in the after-tax amount of $0.5 million
for the three months ended Sept. 30, 2011, while after-tax indirect
corporate costs and inter-segment interest expense not reclassified
to discontinued operations for the nine months ended Sept. 30, 2012
and 2011 totaled $1.6 million and $1.5 million, respectively.

Three Months Ended Sept. 30,

Nine Months Ended Sept. 30,

2012

2011

2012

2011

Weighted average common shares outstanding (in thousands):

Basic

43,847

39,145

43,792

39,105

Diluted

44,108

39,145

44,026

39,792

Earnings per share:

Basic -

Continuing Operations

$

0.79

$

(0.29

)

$

1.31

$

0.55

Discontinued Operations

—

0.02

(0.16

)

0.07

Total Basic Earnings Per Share

$

0.79

$

(0.27

)

$

1.15

$

0.62

Diluted -

Continuing Operations

$

0.78

$

(0.29

)

$

1.31

$

0.54

Discontinued Operations

—

0.02

(0.16

)

0.07

Total Diluted Earnings Per Share

$

0.78

$

(0.27

)

$

1.15

$

0.61

DIVIDENDS

On Oct. 30, 2012, the company’s board of directors declared a quarterly
dividend on common stock. Common shareholders of record at the close of
business on Nov. 16, 2012 will receive $0.37 per share, equivalent to an
annual dividend rate of $1.48 per share, payable on Dec. 1, 2012.

2012 EARNINGS GUIDANCE REAFFIRMED

Black Hills reaffirms expected 2012 earnings per share from continuing
operations, as adjusted, to be in the range of $1.90 to $2.10, as
previously issued on May 3, 2012. Assuming normal weather in the fourth
quarter, earnings for the year are expected to be in the upper half of
the guidance range.

2013 EARNINGS GUIDANCE INITIATED

Black Hills expects 2013 earnings per share from continuing operations,
as adjusted, to be in the range of $2.20 to $2.40 per share based on the
following assumptions:

Capital spending of $440 million to $470 million, including oil and
gas capital expenditures of $90 million to $105 million;

No significant unplanned outages at any of our power generation
facilities;

Oil and natural gas production in the range of 9.3 to 10.3 Bcf
equivalent;

Oil and natural gas annual average NYMEX prices of $3.62 per MMBtu for
natural gas and $91.78 per Bbl for oil; production-weighted average
well-head prices of $2.56 per MMBtu and $81.61 per Bbl of oil, and
average hedged prices received of $2.69 per MMBtu and $84.92 per Bbl;

Oil and natural gas depletion expense in the range of $1.35 to $1.55
per Mcfe;

Exclusion of mark-to-market changes on certain interest rate swaps;

No equity financing in 2013 except for approximately $3 million from
the dividend reinvestment program; and

No significant acquisitions or divestitures.

CONFERENCE CALL AND WEBCAST

Black Hills Corp. will host a live conference call and webcast at 11
a.m. EST on Thursday, Nov. 8, 2012, to discuss the company’s financial
and operating performance.

To access the live webcast and download a copy of the investor
presentation, go to the Black Hills website at www.blackhillscorp.com,
and click on “Webcast” in the “Investor Relations” section. The
presentation will be posted on the website before the webcast. Listeners
should allow at least five minutes for registering and accessing the
presentation. Those interested in asking a question during the live
broadcast or those without Internet access can call 800-706-7741 if
calling within the United States. International callers can call
617-614-3471. All callers need to enter the pass code 37156059 when
prompted.

For those unable to listen to the live broadcast, a replay will be
available on the company’s website or by telephone through Thursday,
Nov. 22, 2012, at 888-286-8010 in the United States and at 617-801-6888
for international callers. The replay pass code is 41048685.

USE OF NON-GAAP FINANCIAL MEASURE

As noted in this news release, in addition to presenting its earnings
information in conformity with Generally Accepted Accounting Principles,
the company has provided non-GAAP earnings data reflecting adjustments
for special items as specified in the GAAP to non-GAAP adjustment
reconciliation table below. Income (loss) from continuing operations, as
adjusted, and Net income (loss), as adjusted, are defined as Income
(loss) from continuing operations and Net income (loss), adjusted for
expenses, gains and losses that the company believes do not reflect the
company’s core operating performance. The company believes that non-GAAP
financial measures are useful to investors because the items excluded
are not indicative of the company’s continuing operating results. The
company’s management uses these non-GAAP financial measures as an
indicator for planning and forecasting future periods. These non-GAAP
measures have limitations as analytical tools and should not be
considered in isolation or as a substitute for analysis of our results
as reported under GAAP. The presentation of these non-GAAP financial
measures should not be construed as an inference that our future results
will be unaffected by other income and expenses that are unusual,
non-routine or non-recurring.

GAAP TO NON-GAAP ADJUSTMENT RECONCILIATION

Three Months Ended Sept. 30,

Nine Months Ended Sept. 30,

(In millions, except per share amounts)

2012

2011

2012

2011

(after-tax)

Income

EPS

Income

EPS

Income

EPS

Income

EPS

Income (loss) from continuing operations (GAAP)

$

34.6

$

0.78

$

(11.2

)

$

(0.29

)

$

57.6

$

1.31

$

21.6

$

0.54

Adjustments, after-tax:

Unrealized (gain) loss on certain interest rate swaps

(0.4

)

(0.01

)

24.9

0.63

1.9

0.04

26.4

0.66

Ceiling test impairment

—

—

—

—

17.3

0.39

—

—

Gain on sale of Williston Basin assets

(17.7

)

(0.40

)

—

—

(17.7

)

(0.40

)

—

—

Incentive compensation - Williston Basin sale

2.2

0.05

—

—

2.2

0.05

—

—

Credit facility fee write off

—

—

—

—

1.0

0.02

—

—

Rounding

—

—

—

0.01

—

—

—

0.01

Total adjustments

(15.9

)

(0.36

)

24.9

0.64

4.7

0.10

26.4

0.67

Income (loss) from continuing operations, as adjusted (non-GAAP)

18.7

0.42

13.7

0.35

62.3

1.41

48.0

1.21

Income (loss) from discontinued operations, net of tax

(0.2

)

—

0.6

0.02

(6.8

)

(0.16

)

2.5

0.07

Net income (loss), as adjusted (non-GAAP)

$

18.5

$

0.42

$

14.3

$

0.37

$

55.5

$

1.25

$

50.5

$

1.28

BUSINESS UNIT PERFORMANCE SUMMARY

Business Group highlights for the three months ended Sept. 30, 2012,
compared to the three months ended Sept. 30, 2011, are discussed below.
The following business group and segment information does not include
certain intercompany eliminations or discontinued operations. Minor
differences in comparative amounts may result due to rounding. All
amounts are presented on a pre-tax basis unless otherwise indicated.
Prior period information has been revised to reclassify information
related to discontinued operations.

Utilities Group

Income from continuing operations for the Utilities Group for the third
quarter ended Sept. 30, 2012, was $14.6 million, compared to $16.4
million in 2011.

Electric Utilities

Three Months Ended

Nine Months Ended

Sept. 30,

Variance

Sept. 30,

Variance

2012

2011

2012 vs. 2011

2012

2011

2012 vs. 2011

(in millions)

Gross margin

$

88.0

$

80.6

$

7.4

$

261.7

$

224.6

$

37.1

Operations and maintenance

34.1

34.8

(0.7

)

110.2

106.1

4.1

Gain on sale of operating asset

—

(0.8

)

0.8

—

(0.8

)

0.8

Depreciation and amortization

18.8

13.2

5.6

56.4

39.1

17.3

Operating income

35.1

33.3

1.8

95.1

80.2

14.9

Interest expense, net

(12.5

)

(9.7

)

(2.8

)

(38.1

)

(29.8

)

(8.3

)

Other (income) expense, net

0.2

0.2

—

1.2

0.6

0.6

Income tax benefit (expense)

(8.2

)

(8.0

)

(0.2

)

(20.8

)

(16.4

)

(4.4

)

Income (loss) from continuing operations

$

14.6

$

15.8

$

(1.2

)

$

37.5

$

34.7

$

2.8

Three Months Ended Sept. 30,

Nine Months Ended Sept. 30,

2012

2011

2012

2011

Operating Statistics:

Retail sales - MWh

1,230,266

1,232,679

3,475,472

3,456,841

Contracted wholesale sales - MWh

88,334

84,346

249,388

256,558

Off-system sales - MWh

288,528

395,769

1,171,198

1,253,385

Total electric sales - MWh

1,607,128

1,712,794

4,896,058

4,966,784

Total gas sales - Cheyenne Light - Dth

352,294

368,702

2,783,273

3,257,335

Regulated power plant availability:

Coal-fired plants (a)

95.4

%

95.1

%

89.1

%

91.6

%

Other plants

98.5

%

98.6

%

96.6

%

95.7

%

Total availability

97.0

%

96.4

%

93.0

%

93.1

%

(a) Nine months ended Sept. 30, 2012 reflects an unplanned outage due to
a transformer failure and a planned outage at Neil Simpson II and a
planned overhaul at Wygen II.

Third Quarter 2012 Compared with Third
Quarter 2011

Gross margin increased primarily due to a
$9.6 million increase related to rate adjustments that include a return
on significant capital investments at Colorado Electric, partially
offset by a $0.7 million decrease in wholesale and transmission margins
as a result of decreased pricing, a decrease of $0.3 million in
off-system sales and a decrease of $0.6 million from expiration of a
reserve capacity agreement with PacifiCorp.

Operations and maintenance decreased
primarily due to a $2.1 million reduction of major maintenance accruals
related to the power plants announced for retirement and cost
containment efforts, partially offset by costs associated with operating
the new generating facility in Pueblo, Colo. including increased
corporate allocations.

Depreciation and amortization increased
primarily due to a higher asset base associated with the new 180
megawatt generating facility constructed in Pueblo, Colo. and the
capital lease assets associated with the 200 megawatt generating
facility providing capacity and energy from Colorado IPP.

Interest expense, net increased primarily
due to interest associated with the financing of the Pueblo generating
facility completed in December 2011. Interest costs were capitalized
during construction in the prior year.

Gas Utilities

Three Months Ended

Nine Months Ended

Sept. 30,

Variance

Sept. 30,

Variance

2012

2011

2012 vs. 2011

2012

2011

2012 vs. 2011

(in millions)

Gross margin

$

39.3

$

39.5

$

(0.2

)

$

149.7

$

163.4

$

(13.7

)

Operations and maintenance

28.3

28.3

—

88.1

91.1

(3.0

)

Depreciation and amortization

6.3

6.1

0.2

18.7

18.0

0.7

Operating income

4.6

5.1

(0.5

)

42.9

54.3

(11.4

)

Interest expense, net

(5.4

)

(6.3

)

0.9

(17.7

)

(19.6

)

1.9

Other expense (income), net

—

—

—

0.1

0.2

(0.1

)

Income tax (expense)

0.8

1.8

(1.0

)

(8.9

)

(10.5

)

1.6

Income (loss) from continuing operations

$

—

$

0.6

$

(0.6

)

$

16.4

$

24.3

$

(7.9

)

Three Months Ended Sept. 30,

Nine Months Ended Sept. 30,

Operating Statistics:

2012

2011

2012

2011

Total gas sales - Dth

5,448,719

5,753,975

31,419,468

39,958,801

Total transport volumes - Dth

14,584,979

14,385,819

46,009,382

44,510,873

Third Quarter 2012 Compared with Third
Quarter 2011

Operating income was comparable to the same
period in the prior year reflecting normal seasonality of our Gas
Utilities.

Income tax benefit (expense): The deviation
in the effective tax rate from the statutory rate is the result of a
favorable true-up adjustment that had a more pronounced impact in 2012
due to significantly lower pre-tax net loss. The prior year also
realized a favorable true up adjustment for flow-through treatment of
certain property-related temporary differences.

Non-Regulated Energy Group

Income from continuing operations from the Non-regulated Energy group
for the three months ended Sept. 30, 2012, was $24.2 million, compared
to $1.0 million for the same period in 2011.

Power Generation

Three Months Ended

Nine Months Ended

Sept. 30,

Variance

Sept. 30,

Variance

2012

2011

2012 vs. 2011

2012

2011

2012 vs. 2011

(in millions)

Revenue

$

21.0

$

8.1

$

12.9

$

59.3

$

23.5

$

35.8

Operations and maintenance

7.8

4.6

3.2

22.5

12.9

9.6

Depreciation and amortization

1.2

1.1

0.1

3.4

3.2

0.2

Operating income

12.0

2.4

9.6

33.4

7.5

25.9

Interest expense, net

(3.1

)

(1.8

)

(1.3

)

(11.8

)

(5.5

)

(6.3

)

Other (income) expense, net

—

—

—

—

1.2

(1.2

)

Income tax benefit (expense)

(3.8

)

(0.3

)

(3.5

)

(5.7

)

(1.1

)

(4.6

)

Income (loss) from continuing operations

$

5.1

$

0.3

$

4.8

$

16.0

$

2.1

$

13.9

Three Months Ended Sept. 30,

Nine Months Ended Sept. 30,

2012

2011

2012

2011

Operating Statistics:

Contracted fleet power plant availability -

Coal-fired plants

99.4

%

97.1

%

99.5

%

98.9

%

Gas-fired plants

99.4

%

100.0

%

99.3

%

100.0

%

Total availability

99.4

%

98.1

%

99.4

%

99.3

%

Third Quarter 2012 Compared with Third
Quarter 2011

Revenue increased due to the commencement
of commercial operation of our new 200 megawatt generating facility in
Pueblo, Colo. on Jan. 1, 2012.

Operations and maintenance increased
primarily due to the costs to operate and corporate allocations relating
to our new 200 megawatt generating facility in Pueblo, Colo., which
began serving customers on Jan. 1, 2012.

Depreciation and amortization was
comparable to the same period in the prior year. The new generating
facility's PPA to supply capacity and energy to Colorado Electric is
accounted for as a capital lease under GAAP; as such, depreciation
expense for the facility is recorded at Colorado Electric for segment
reporting purposes.

Interest expense, net increased due to
interest costs for financing the Pueblo generating facility. Interest
costs were capitalized during construction in the prior year.

Coal Mining

Three Months Ended

Nine Months Ended

Sept. 30,

Variance

Sept. 30,

Variance

2012

2011

2012 vs. 2011

2012

2011

2012 vs. 2011

(in millions)

Revenue

$

14.7

$

17.8

$

(3.1

)

$

42.8

$

48.9

$

(6.1

)

Operations and maintenance

10.8

14.2

(3.4

)

32.1

41.8

(9.7

)

Depreciation, depletion and amortization

2.9

5.2

(2.3

)

9.6

14.4

(4.8

)

Operating income (loss)

1.0

(1.5

)

2.5

1.1

(7.2

)

8.3

Interest income, net

—

1.0

(1.0

)

1.2

2.9

(1.7

)

Other income (expense)

0.5

0.5

—

2.1

1.7

0.4

Income tax benefit (expense)

0.2

0.5

(0.3

)

(0.4

)

1.6

(2.0

)

Income (loss) from continuing operations

$

1.7

$

0.6

$

1.1

$

3.9

$

(1.1

)

$

5.0

Three Months Ended Sept. 30,

Nine Months Ended Sept. 30,

2012

2011

2012

2011

Operating Statistics:

(in thousands)

Tons of coal sold

1,105

1,550

3,191

4,155

Cubic yards of overburden moved

1,827

3,873

6,749

10,261

Third Quarter 2012 Compared with Third
Quarter 2011

Revenue decreased primarily due to a 29
percent decrease in tons sold as a result of the December 2011
expiration of an unprofitable train load-out contract which represented
approximately 29 percent of our tons sold in 2011, partially offset by
an increase in average sales price as a result of price escalators and
adjustments in certain of our sales contracts. Approximately 50 percent
of our current coal production is sold under contracts that include
price adjustments based on actual mining costs.

Operations and maintenance decreased
primarily from reduced overburden moved related to lower sales volumes
and mining efficiencies, including decreased fuel costs and headcount
reductions as a result of the revised mine plan and termination of the
train load-out contract at Dec. 31, 2011.

Interest income, net decreased primarily
due to a decrease in inter-company notes receivable upon payment of a
dividend to our parent.

Income tax benefit (expense) benefited from
a change in the effective tax rate which was primarily due to the impact
of percentage depletion and a tax return true-up.

Oil and Gas

Three Months Ended

Nine Months Ended

Sept. 30,

Variance

Sept. 30,

Variance

2012

2011

2012 vs. 2011

2012

2011

2012 vs. 2011

(in millions)

Revenue

$

24.7

$

19.2

$

5.5

$

67.0

$

55.9

$

11.1

Operations and maintenance

12.1

9.6

2.5

33.3

30.3

3.0

Depreciation, depletion and amortization

12.5

7.7

4.8

34.8

22.6

12.2

Gain on sale of operating assets

(27.3

)

—

(27.3

)

(27.3

)

—

(27.3

)

Impairment of long-lived assets

—

—

—

26.9

—

26.9

Operating income

27.4

1.9

25.5

(0.7

)

2.9

(3.6

)

Interest expense, net

(1.1

)

(1.5

)

0.4

(3.9

)

(4.2

)

0.3

Other (income) expense

0.1

0.1

—

0.2

—

0.2

Income tax benefit (expense), net

(9.0

)

(0.2

)

(8.8

)

2.2

0.8

1.4

Income (loss) from continuing operations

$

17.4

$

0.2

$

17.2

$

(2.2

)

$

(0.6

)

$

(1.6

)

Percentage

Percentage

Three Months Ended Sept. 30,

Increase

Nine Months Ended Sept. 30,

Increase

Operating Statistics:

2012

2011

(Decrease)

2012

2011

(Decrease)

Bbls of crude oil sold

184,423

98,950

86

%

485,262

303,401

60

%

Mcf of natural gas sold

2,278,801

2,147,172

6

%

7,119,087

6,264,460

14

%

Gallons of NGL sold

1,099,198

993,752

11

%

2,751,409

2,847,011

(3

)%

Mcf equivalent sales

3,542,367

2,882,837

23

%

10,423,717

8,491,582

23

%

Depletion expense/Mcfe

$

3.26

$

2.38

37

%

$

3.07

$

2.38

29

%

Three Months Ended Sept. 30, 2012

Three Months Ended Sept. 30, 2011

Natural Gas

Natural Gas

Average Prices

Crude Oil

Natural Gas

Liquids

Crude Oil

Natural Gas

Liquids

(Bbl)

(MMcf)

(gallons)

(Bbl)

(MMcf)

(gallons)

Average hedged price received

$

88.69

$

3.07

$

0.65

$

82.76

$

4.24

$

0.88

Average well-head price

$

88.83

$

1.87

$

85.07

$

3.00

Nine Months Ended Sept. 30, 2012

Nine Months Ended Sept. 30, 2011

Natural Gas

Natural Gas

Average Prices

Crude Oil

Natural Gas

Liquids

Crude Oil

Natural Gas

Liquids

(Bbl)

(MMcf)

(gallons)

(Bbl)

(MMcf)

(gallons)

Average hedged price received

$

81.65

$

3.27

$

0.77

$

76.25

$

4.39

$

0.94

Average well-head price

$

84.33

$

1.61

$

88.12

$

2.87

Third Quarter 2012 Compared with Third
Quarter 2011

Revenue increased primarily due to an 86
percent increase in crude oil sales, due primarily to activities from
new wells in our drilling program in the Bakken shale formation and a 7
percent increase in the average price received for crude oil sold. A 6
percent increase in natural gas and NGL volumes, due primarily to the
production from three Mancos formation test wells in the San Juan and
Piceance Basins, was partially offset by a 28 percent decrease in the
average price received for natural gas.

Operations and maintenance costs increased
primarily due to higher costs from non-operated wells and higher
compensation and benefit costs.

Depreciation, depletion and amortization
increased primarily due to the year-to-date impact from adjusting
expected 2012 reserve additions due to the deferred drilling activities
in the San Juan Mancos formation, as well as higher cost reserves
associated with our Bakken activities and a higher depletion rate per
Mcfe on higher volumes.

Gain on sale of operating assets represents
the gain on the sale of our Williston Basin assets. We follow the
full-cost method of accounting for oil and gas activities, which
typically does not allow for gain on sale recognition unless such
adjustments would significantly alter the relationship between
capitalized costs and proved reserves. The remainder of the sales
amount, not recognized as gain, reduces the full-cost pool and should
significantly decrease the future depreciation, depletion and
amortization rate.

Income tax (expense) benefit: For 2012, the
benefit generated by percentage depletion had a significantly reduced
impact on the effective tax rate compared to the same period in 2011.

Corporate

Third Quarter 2012 Compared with Third
Quarter 2011

Loss from continuing operations for Corporate was $4.2 million for the
three months ended Sept. 30, 2012 compared to loss from continuing
operations of $28.6 million for the three months ended Sept. 30, 2011.
The variance from the prior year was primarily as a result of an
incentive compensation accrual recorded as a result of the Williston
Basin asset sale and an unrealized, non-cash mark-to-market gain on
certain interest rate swaps for the quarter ended Sept. 30, 2012 of
approximately $0.6 million compared to a loss of $38.2 million
unrealized, non-cash mark-to-market loss on these interest rate swaps in
the prior year.

Discontinued Operations

Third Quarter 2012 Compared with Third
Quarter 2011

On Feb. 29, 2012, the company sold the outstanding stock of Enserco
Energy Inc., our Energy Marketing segment, which resulted in this
segment being reported as discontinued operations. Cash proceeds were
approximately $166.3 million, subject to final post-closing adjustments.
For comparative purposes, all prior results of our Energy Marketing
segment have been restated to reflect the reclassification of this
segment to discontinued operations on a consistent basis.

For the three months ended Sept. 30, 2012, we recorded a loss from
discontinued operations of $0.2 million.

Pursuant to the provisions of the stock purchase agreement, the buyer
requested purchase price adjustments totaling $7.2 million. We contested
this proposed adjustment and estimated the amount owed at $1.4 million,
which is accrued for in the loss from discontinued operations for the
nine months ended Sept. 30, 2012. If we do not reach a negotiated
agreement with the buyer regarding the purchase price adjustment,
resolution will occur through the dispute resolution provision of the
stock purchase agreement.

ABOUT BLACK HILLS CORP.

Black Hills Corp. (NYSE: BKH) – a diversified energy company with a
tradition of exemplary service and a vision to be the energy partner of
choice – is based in Rapid City, S.D., with corporate offices in Denver
and Papillion, Neb. The company serves 765,000 natural gas and electric
utility customers in Colorado, Iowa, Kansas, Montana, Nebraska, South
Dakota and Wyoming. The company's non-regulated businesses generate
wholesale electricity, and produce natural gas, crude oil and coal.
Black Hills employees partner to produce results that improve life with
energy. More information is available at www.blackhillscorp.com.

CAUTION REGARDING FORWARD-LOOKING STATEMENTS

This news release includes “forward-looking statements” as defined by
the Securities and Exchange Commission, or SEC. We make these
forward-looking statements in reliance on the safe harbor protections
provided under the Private Securities Litigation Reform Act of 1995. All
statements, other than statements of historical facts, included in this
news release that address activities, events or developments that we
expect, believe or anticipate will or may occur in the future are
forward-looking statements. This includes, without limitations, our 2012
and 2013 earnings guidance. These forward-looking statements are based
on assumptions which we believe are reasonable based on current
expectations and projections about future events and industry conditions
and trends affecting our business. However, whether actual results and
developments will conform to our expectations and predictions is subject
to a number of risks and uncertainties that, among other things, could
cause actual results to differ materially from those contained in the
forward-looking statements, including without limitation, the risk
factors described in Item 1A of Part I of our 2011 Annual Report on Form
10-K filed with the SEC, and other reports that we file with the SEC
from time to time, and the following:

The accuracy of our assumptions on which our earnings guidance is
based;

Our ability to continue our continuous improvement program and
cost-reduction efforts to mitigate the impacts of earnings challenges
in the first quarter through the remainder of 2012;

Our ability to obtain adequate cost recovery for our utility
operations through regulatory proceedings and favorable rulings in
periodic applications to recover costs for capital additions, fuel,
transmission and purchased power and the timing in which the new rates
would go into effect;

Our ability to complete our capital program in a cost-effective and
timely manner;

Our ability to successfully resolve the purchase price adjustments
relating to the sale of Enserco Energy Inc.; and

Other factors discussed from time to time in our filings with the SEC.

New factors that could cause actual results to differ materially from
those described in forward-looking statements emerge from time-to-time,
and it is not possible for us to predict all such factors, or the extent
to which any such factor or combination of factors may cause actual
results to differ from those contained in any forward-looking statement.
We assume no obligation to update publicly any such forward-looking
statements, whether as a result of new information, future events or
otherwise.

(Minor differences may result due to rounding.Prior
period information has been revised to reclassify information related to
discontinued operations.)

Consolidating Income Statement

Electric

Power

Utility

Generation

Electric

Gas

Power

Coal

Oil and

Inter-Co

Inter-Co

Other Inter-Co

Three Months Ended Sept. 30, 2012

Utilities

Utilities

Generation

Mining

Gas

Corporate

Lease Elim*

Lease Elim*

Eliminations

Total

(in millions)

Revenue

$

151.3

$

63.4

$

1.3

$

6.1

$

24.7

$

—

$

—

$

—

$

—

$

246.8

Intercompany revenue

3.7

—

19.7

8.6

—

47.3

—

0.4

(79.7

)

—

Fuel, purchased power and cost of gas sold

67.0

24.2

—

—

—

—

0.8

—

(29.4

)

62.6

Gross Margin

88.0

39.2

21.0

14.7

24.7

47.3

(0.8

)

0.4

(50.3

)

184.2

Operations and maintenance

34.1

28.3

7.8

10.8

12.1

46.8

—

—

(47.6

)

92.3

Gain on sale of operating asset

—

—

—

—

(27.3

)

—

—

—

—

(27.3

)

Depreciation, depletion and amortization

18.8

6.3

1.2

2.9

12.5

2.8

(3.3

)

3.0

(2.8

)

41.4

Impairment of long-lived assets

—

—

—

—

—

—

—

—

—

—

Operating income

35.1

4.6

12.0

1.0

27.4

(2.3

)

2.5

(2.6

)

0.1

77.8

Interest expense, net

(13.6

)

(5.9

)

(3.2

)

—

(1.1

)

(20.5

)

—

—

18.1

(26.2

)

Interest rate swaps - unrealized (loss) gain

—

—

—

—

—

0.6

—

—

—

0.6

Interest income

1.1

0.5

0.1

—

—

16.2

—

—

(17.5

)

0.4

Other income (expense)

0.2

—

—

0.5

0.1

6.6

—

—

(7.4

)

—

Income tax benefit (expense)

(8.2

)

0.8

(3.8

)

0.2

(9.0

)

2.0

(0.9

)

0.9

—

(18.0

)

Income (loss) from continuing operations

$

14.6

$

—

$

5.1

$

1.7

$

17.4

$

2.6

$

1.6

$

(1.7

)

$

(6.7

)

$

34.6

* The new generating facility constructed by Black Hills Colorado IPP at
our Pueblo Airport Generation site which sells energy and capacity under
a 20-year PPA to Colorado Electric is accounted for as a capital lease.
Therefore, revenue and expense of the Electric Utilities and Power
Generation segments reflect adjustments for lease accounting which are
eliminated in consolidation.

Consolidating Income Statement

Electric

Power

Utility

Generation

Other

Electric

Gas

Power

Coal

Oil and

Inter-Co

Inter-Co

Inter-Co

Nine Months Ended Sept. 30, 2012

Utilities

Utilities

Generation

Mining

Gas

Corporate

Lease Elim*

Lease Elim*

Eliminations

Total

(in millions)

Revenue

$

452.0

$

314.3

$

3.2

$

18.5

$

67.0

$

—

$

—

$

—

$

—

$

855.0

Intercompany revenue

11.9

—

56.1

24.3

—

143.9

—

1.2

(237.4

)

—

Fuel, purchased power and cost of gas sold

202.2

164.6

—

—

—

0.1

2.4

—

(86.1

)

283.2

Gross margin

261.7

149.7

59.3

42.8

67.0

143.8

(2.4

)

1.2

(151.3

)

571.8

Operations and maintenance

110.2

88.1

22.5

32.1

33.3

135.2

—

—

(139.0

)

282.4

Gain on sale of operating asset

—

—

—

(27.3

)

—

—

—

—

(27.3

)

Depreciation, depletion and amortization

56.4

18.7

3.4

9.6

34.8

8.1

(9.8

)

8.2

(8.0

)

121.4

Impairment of long-lived assets

—

—

—

—

26.9

—

—

—

—

26.9

Operating income

95.1

42.9

33.4

1.1

(0.7

)

0.5

7.4

(7.0

)

(4.3

)

168.4

Interest expense, net

(44.8

)

(20.1

)

(12.3

)

—

(3.9

)

(64.0

)

—

—

63.0

(82.1

)

Interest rate swaps - unrealized (loss) gain

—

—

—

—

—

(2.9

)

—

—

—

(2.9

)

Interest income

6.8

2.4

0.5

1.2

—

48.0

—

—

(57.5

)

1.4

Other income (expense)

1.2

0.1

—

2.0

0.2

30.3

—

—

(31.1

)

2.7

Income tax benefit (expense)

(20.8

)

(8.9

)

(5.6

)

(0.4

)

2.2

3.6

(2.7

)

2.5

0.2

(29.9

)

Income (loss) from continuing operations

$

37.5

$

16.4

$

16.0

$

3.9

$

(2.2

)

$

15.5

$

4.7

$

(4.5

)

$

(29.7

)

$

57.6

* The new generating facility constructed by Black Hills Colorado IPP at
our Pueblo Airport Generation site which sells energy and capacity under
a 20-year PPA to Colorado Electric is accounted for as a capital lease.
Therefore, revenue and expense of the Electric Utilities and Power
Generation segments reflect adjustments for lease accounting which are
eliminated in consolidation.

Consolidating Income Statement

Electric

Gas

Power

Coal

Intercompany

Three Months Ended Sept. 30, 2011

Utilities

Utilities

Generation

Mining

Oil and Gas

Corporate (a)

Eliminations

Total

(in millions)

Revenue

$

151.0

$

72.7

$

1.0

$

9.2

$

19.2

$

—

$

—

$

253.1

Intercompany revenue

2.7

—

7.1

8.6

—

46.2

(68.2

)

(3.6

)

Fuel, purchased power and cost of gas sold

73.1

33.2

—

—

—

—

(20.2

)

86.1

Gross margin

80.6

39.5

8.1

17.8

19.2

46.2

(48.0

)

163.4

Operations and maintenance

34.8

28.3

4.6

14.2

9.6

41.0

(42.0

)

90.5

Depreciation, depletion and amortization

13.3

6.1

1.1

5.1

7.7

2.8

(2.8

)

33.3

Operating income

33.3

5.1

2.4

(1.5

)

1.9

2.4

(4.0

)

39.6

Interest expense, net

(13.4

)

(7.8

)

(2.2

)

—

(1.5

)

(23.7

)

25.8

(22.8

)

Interest rate swaps - unrealized (loss) gain

—

—

—

—

—

(38.2

)

—

(38.2

)

Interest income

3.7

1.5

0.4

1.0

—

16.4

(22.5

)

0.5

Other income (expense)

0.2

—

—

0.5

—

3.1

(3.1

)

0.7

Income tax benefit (expense)

(8.0

)

1.8

(0.3

)

0.5

(0.2

)

14.9

0.3

9.0

Income (loss) from continuing operations

$

15.8

$

0.6

$

0.3

$

0.5

$

0.2

$

(25.1

)

$

(3.5

)

$

(11.2

)

(a)

Certain direct corporate costs and inter-segment interest expense
previously allocated to our Energy Marketing segment were not
reclassified to discontinued operations but included in the
Corporate segment.

Consolidating Income Statement

Electric

Gas

Power

Coal

Intercompany

Nine Months Ended Sept. 30, 2011

Utilities

Utilities

Generation

Mining

Oil and Gas

Corporate (a)

Eliminations

Total

(in millions)

Revenue

$

431.6

$

402.8

$

2.6

$

23.1

$

55.9

$

—

$

—

$

916.0

Intercompany revenue

9.9

—

20.9

25.8

—

142.1

(203.7

)

(5.0

)

Fuel, purchased power and cost of gas sold

216.9

239.4

—

—

—

0.1

(55.9

)

400.5

Gross margin

224.6

163.4

23.5

48.9

55.9

142.0

(147.8

)

510.5

Operations and maintenance

106.1

91.1

12.9

41.8

30.3

125.8

(129.0

)

279.0

Depreciation, depletion and amortization

39.1

18.0

3.1

14.4

22.6

8.2

(8.0

)

97.4

Operating income

80.2

54.3

7.5

(7.3

)

3.0

8.0

(11.6

)

134.1

Interest expense, net

(40.5

)

(24.0

)

(6.6

)

—

(4.2

)

(69.0

)

75.3

(69.0

)

Interest rate swaps - unrealized (loss) gain

—

—

—

—

—

(40.6

)

—

(40.6

)

Interest income

10.7

4.3

1.2

2.9

—

46.8

(64.4

)

1.5

Other income (expense)

0.6

0.2

1.1

1.7

(0.1

)

32.9

(32.9

)

3.5

Income tax benefit (expense)

(16.4

)

(10.5

)

(1.1

)

1.6

0.7

17.5

0.3

(7.9

)

Income (loss) from continuing operations

$

34.6

$

24.3

$

2.1

$

(1.1

)

$

(0.6

)

$

(4.4

)

$

(33.3

)

$

21.6

(a)

Certain direct corporate costs and inter-segment interest expense
previously allocated to our Energy Marketing segment were not
reclassified to discontinued operations but included in the
Corporate segment.